Valve system for a well packer



Dec. M, 1969 R. M. M EVER, JR

VALVE SYSTEM FOR A WELL PACKER 3 Sheets-Sheet 1 Original Filed Oct. 5,1967 1 N VENT OR. JMMMM Dec. 16, 1969 R. M. MCE JR 3,483,922

VALVE SYSTEM FOR A WELL PACKER Original Filed Oct. 5, 1967 3Sheets-Sheet 2 United States Patent 0 ABSTRACT OF THE DISCLOSURE Theparticular embodiment described herein was illustrative of one form ofthe invention is a well packer valve system including a rotary valvesleeve for opening and closing a flow passage through the well packer,tubular valve actuating means sealingly siidable in the flow passage andhaving one end portion releasably coupled to the valve sleeve and theother end portion adapted for connection to a pipe string, coengageablemeans for rotating the actuating means and valve sleeve in response tosuecessive downward and upward movements of the pipe string, and meansfor limiting alternate upward movement of the pipe string.

This is a division of application Ser. No. 673,176, filed 3 Oct. 5, 1967now Patent No. 3,433,301.

This invention relates generally to well packers, and more specificallyto a new and improved well packer apparatus having a flow passage and amechanically actuated valve system for opening and closing the flowpassage to fluid flow.

It is often desirable in connection with Wells to seal off the well borewhile providing controlled fluid communication to a well zone below thesealing point. For example, it may be desirable to squeeze cement belowa packer through a pipe string at a predetermined point behind liner orcasing. Such an operation is advantageous in preventing communicationwith other zones; closing channels, etc., before a particular zone isput on production. Or, it may be desirable to reperforate a well zone,and cement is squeezed to close old perforations. Further, it might bedesirable to abandon a well zone and cement may be used to squeeze offthe zone.

In any event, an apparatus commonly known as a cement or squeezeretainer packer may be used to isolate the zone which is to bepressurized from well fluids in the remainder of the well bore. Suchpackers have valving which can be closed after squeezing is completed inorder to retain the cement below the packet at developed pressures.Commonly, such valving has taken the form of check valve type systemswhich readily permit fluid flow into the isolated zone from the pipestring but which prevent reverse flow. Check type valves, however, whilefunctioning to hold the back pressure of the squeeze, aredisadvantageous because such systems do not prevent loss of mud to theformation when low break-down pressures are encountered, do not keepannulus fluids off weak formations when the pipe string is removed, anddo not permit the use of batch squeeze operations. Moreover, in order tocompletely bridge the well bore against fluid flow in either directionafter a cementing operation has been completed, a shut-oft plug or thelike must be placed in the packer bore.

In view of the foregoing disadvantages encountered with check type valvesystems, various so called pressure balanced valve systems have comeinto usage. Such valve systems, usually being comprised of a verticallymovable 3,483,922 Patented Dec. 16, 1969 sleeve which is opened andclosed mechanically by manipulation of the pipe string at the top of thewell bore, will hold pressure from above or below when closed and thusalleviate most of the aforementioned problems. However, mechanicalactuation of a valve system which may be located many thousands of feetdown in a well has heretofore required a great deal of guesswork on thepart of the operator in knowing the exact condition of the valve duringopening and closing movements of same. Consequently, prior systems havenot been highly reliable in operation and have been subject tomalfunctions due to failure to close when it is desired to hold backpressure, or inability to subsequently reopen the valve after closingfor additional fluid displacement. Moreover, it has not heretofore beenpossible to attain complete control over tubing and annulus pressureswhen squeezing is completed and it is desired to close the valve.

The present invention provides a new and improved well packer valvesystem which has all the advantages of pressure balanced systems andwhich is mechanically operated in a positive and reliable manner. Thevalve system is structurally arranged to be actuated in response tosuccessive upward and downward movements of the pipe string, so that anoperator is always appraised of the open or closed condition of thevalve and can not inadvertently open or close it. Accordingly, theoperation of the present valve system is very positive and completepressure control is always attained.

The present invention may be summarized to further point out the variousconcepts involved, as a well packer apparatus including a mandrel havinga flow passage and a rotary valve sleeve in the flow passage for openingand closing the passage. A tubular valve actuating member is sealinglyslidable in the flow passage and has a lower end portion releasablycoupled to the valve sleeve in order to rotate it, and an upper endportion which is adapted for connection to the pipe string. Coengageablemeans including a guideway and index means is provided to effectrotation of the actuating member, and thus the valve sleeve, in responseto successive downward and upward longitudinal movements of the pipestring, and the coengageable means can further include means forlimiting alternate upward movements and successive downward movements ofthe pipe string. Thus it will be apparent that the valve system of thepresent invention is mechanically operable in a simple and positivemanner by longitudinal motion of the pipe string at the earths surface.

The present invention has other concepts and advantages which willbecome more clearly apparent in connection with the following detaileddescription. A preferred embodiment is shown in the accompanyingdrawings, in which:

FIGURES 1A and 1B are longitudinal sectional views, with portions inside elevation, of an embodiment which will illustrate the principles ofthe present invention with parts in relative positions for lowering intoa well bore, FIGURE 1B forming a lower continuation of FIG- URE 1A;

FIGURE 2 is an isometric view of the rotary valve element;

FIGURE 3 is a fragmentary developed view of a coupling mechanism inaccordance with the present in vention;

FIGURE 4 is a fragmentary developed view to illustrate the torquetransmission structure between the extension and valve sleeve;

FIGURE 5 is a fragmentary developed view of the extension slot system inaccordance with the present invention;

FIGURE 6 is a cross section on line 6-6 of FIG- URE 1A; and

FIGURES 7A and 7B are views similar to FIGURES 1A and 1B except withparts of the present invention in their cooperative positions when setin a well bore.

With initial reference to FIGURES 1A and 1B, apparatus which willillustrate the principles of the present invention includes a mechanicalsetting tool A and a well packer B having a valve system C. The settingtool A is utilized in setting the packer B in a well bore so that thepacker B can function to pack off the well bore. The valve system Ccontrols fluid communication to the well bore below the packer B. Theentire apparatus can be lowered into the well on a running-in string 1%of tubing or drill pipe which provides a fluid conduit extending to thetop of the well, as well as a mechanical member which can be manipulatedat the top of the well bore t eflect operation of the setting tool A andthe valve assembly C.

As shown in FIGURE 1B, the packer B has a central body or mandrel 11having a bore 12 which provides a fluid passageway and further has alower guide portion 13 which supports lower slips 14. The slips 14 cantake any desired form, such as frangible, segmented, or integralexpansible type slips. A lower expander cone 15 is arranged to shift thelower slips 14 outwardly and a conventional packing structure 16surrounds the mandrel 11 between the lower expander cone and an upperexpander cone 17. Typical anti-extrusion rings 18, 18a

can confine the end portions of the packing 16, and I shear pins 19,1911 or other suitable means can releasably couple the expander cones 15and 17 to the mandrel 11 to control the relative motion sequence betweenparts in any desired manner. A conventional split ratchet ring 20 isarranged between the upper expander cone 17 and the mandrel 11 andcooperates with external teeth 21 on the mandrel to trap compressionloading in the packing structure 16 when the well packer B is set.

The lower guide portion 13 of the mandrel 11 is constituted as a valvebody having a central flow passage 24 which is closed in a fluid tightmanner at its lower end by a plug 25. Diametrically opposed side ports26 in the valve body 13 are provided to communicate with the wellannulus below the packing element 16. A valve sleeve 27 is locatedwithin the passage 24 adjacent to the side ports 26 and is arranged formovement between various rotational positions about the longitudinalaxis of the mandrel 11 to control fluid flow from the passage 24 throughthe side ports 26. In one rotational position, lateral ports 28 in thevalve sleeve 27 are aligned with the side I ports 26 in the valve body13 to permit fluid flow. In other rotational positions of the valvesleeve 27, the ports 26 and 28 are not in registry and the passage 24 isclosed to fluid flow in either direction.

As shown in FIGURE 2, the valve sleeve 27 is generally tubular in formand has appropriate external grooves for a seal structure which caninclude upper and lower annular seals 29 and 30 which are connected byvertically extending seals 31 and 32 located on either side of the ports28. With this type of seal configuration, the side seals 31 and 32together with the seal portions 33 and 34 above and below the ports 28prevent fluid flow through the ports, while the entirety of the upperand lower seals 29 and 30 precludes flow through the body ports 26. Inthe alternative, it will be appreciated that the seal arrangement couldinclude face seals which surround the sleeve ports 28 to prevent flow ineither direction through the sleeve ports, along with upper and lowerannular sleeve seals above and below the face seals to prevent flow ineither direction through the body ports 26. Radially inwardly extendingpins 35 on the valve sleeve 27 provide a means for applying rotationforce or torque to the valve sleeve 27 to rotate it between its variouspositions.

With particular reference to FIGURE 1A, the setting tool assembly Aincludes a central operating mandrel 38 having an open bore 39 and whichcan be connected to the lower end of the tubing string 10 by a threadedcollar 4%) or the like. The lower end portion of the operating mandrel38 is provided with a swivel connection 41 to a tubular extensionassembly which includes an enlarged sub 42 arranged to engage the upperend of the packer mandrel 11 and a tubular extension which telescopeswithin the bore 12 of the packer mandrel. The sub 42 and extension 45are threaded together at 43 in a fluid tight manner. A swivel sleeve 44is coupled to the upper portion of the sub 42 and has an inwardlyextending shoulder section 46 forming an annular space 47 whichrotatably received an outwardly extending section 43 on the operatingmandrel 38. Accordingly, it will be apparent that the extension 45 andsub 42 can turn or rotate relative to both the operating mandrel 38 andthe tubing 10. Appropriate seals such as O-rings 49 and 50 can beprovided, the lower seal 50 preventing fluid leakage from the bore ofthe mandrel 38 at the swivel connection 41, and the upper seal 49protecting the swivel connection from ambient well fluids and debris.

The extension 45 is telescoped within the bore of the packer mandrel 11and has arcuate coupling lugs 52 which can engage within an elongateinternal mandrel recess 53. The recess 53, shown in an inside developedview in FIG- URE 3, is open to the top of the packer mandrel 11 byvertically extending slots 54 and located on circumferentially oppositesides of the bore of the mandrel. Thus. the coupling lugs 52 can beinserted into the recess 53 via the slots 54 and 55 and roation of theextension 45 relative to the mandrel 11 will position the lugs 52underneath mandrel shoulders 56 formed between the slots. With thisrelationship of parts, engagement of the coupling lugs 52 with theshoulders 56 will limit upward movement of the extension 45 relative tothe mandrel 11, and engagement of the sub 42 with the upper end surfaceof the mandrel 11 will limit downward movement. Accordingly, when thelugs 52 are underneath the shoulders 56, the extension 45 is coupled forlimited reciprocating motion relative to the mandrel 11, and when thelugs are aligned with the slots 54, 55, the extension can be insertedwithin, or withdrawn from, the bore 12 of the mandrel 11.

The lower end of the extension 45 is open at 57 and side ports 58 areprovided for fluid flow. When the extension 45 is telescoped within thepacker mandrel 11 as shown in FIGURE 1B the lower end portion 59 of theextension 45 is located within the valve sleeve 27. A torque sleeve 60is threaded onto the lower end portion 59, and properly positionedthereon as by a screw 61 or the like, and has upwardly extending sideguide slots 62 which are flared and open at the lower end of the sleeve60. The slots 62 receive the valve sleeve pins 35 so that rotation ofthe extension 45 will impart corresponding rotation to the valve sleeve27. Each of the side slots 62, one of which is shown in developed viewin FIGURE 4, has a longitudinal portion 63 of sufficient vertical extentwhereby the extension 45 can be moved upwardly and downwardly apredetermined amount and still be co-rotatively coupled to the valvesleeve 27. Moreover, the slots 60 each have an upper circumferentiallyenlarged portion 64 to permit the valve sleeve 27 to be rotated to acertain extent relative to the extension 45 and in a direction which isopposite to its normal direction of rotation for purposes which will behereafter explained. The upper end of the torque sleeve 60 can be madeto terminate below an outwardly extending shoulder 65 on the extension45 to provide an annular recess in which a seal structure 66 is located.The seal structure 66, which can take many forms, is shown as one ormore metallic rings 67 having inner and outer grooves which receivesuitable seals 68 and 69. Thus arranged, the seal structure 66 preventsfluid leakage between the packer mandrel 11 and the extension 45 whenthe latter is telescoped within the former.

Upper slip segments 72 are mounted at the upper end portion of thepacker mandrel 11 adjacent to the upper expander cone 17. The segments72 have upwardly facing wickers or teeth 73 on their outer peripheries,as well as inner inclined surfaces 74 which are engageable with outerinclined surfaces 75 on the expander cone 17 for shifting the segmentsoutwardly into gripping engagement with well casing. The extension sub42 and the packer mandrel 11 are respectively provided with annulargrooves 76 and 77 and the slip segments 72 can have correspondingshoulders 78 and 79 which engage within the grooves to limit verticalmovement of the slip segments in their retracted positions. A retainersleeve 80, which forms a part of the setting tool A, extends downwardlyin encompassing relation over upper portions 81 of the slip segments toretain them inwardly as long as the retainer sleeve occupies therelative position shown in FIGURES 1A and 1B. It will be appreciatedthat due to the engaging conditions of the shoulders 78 and 79 withinthe grooves 76 and 77, and to the holding action of the retainer sleeve80, the slip segments 72 are quite rigidly held inwardly in retractedpositions to prevent any likelihood of premature setting during loweringinto a well.

Further to the setting tool assembly A, a control sleeve 88 (FIGURE 1A)is slidably and co-rotatively secured to the operating mandrel 38 bysplines 89 or the like. The control sleeve 88 is initially locked in anupper position on the mandrel 38 by several latch lugs 90 which engagein a mandrel detent 91. A drag mechanism 92 including a tubular cage 93is initially secured in a lower position on the control sleeve bycoengaging right-hand threads 94. Typical drag blocks 95 are carried bythe cage 93 and are urged outwardly by coil springs 96 to frictionallyengage casing and resist motion in a conventional manner. An innersurface 97 on the cage 93 holds the latch lugs 90 inwardly in engagementwith the mandrel detent 19 while the parts are in the relative positionsfor lowering into a well bore.

The slip retainer sleeve 80 extends downwardly from the cage 93 toencompass the upper end portions 81 of the upper slip segments 72 as waspreviously described. When desired, it will be appreciated thatright-hand rotation of the operating mandrel 38 by the running-in string10 will rotate the control sleeve 88 relative to the drag mechanism 92,and, due to the interengagement of the threads 94, cause the dragmechanism and the retainer sleeve 80 to feed upwardly along the controlsleeve 88, thereby removing the retainer sleeve from encompassingrelation to the upper portions of the slips 72. Upward feeding of thedrag mechanism 92 will also position an internal cage t recess 100opposite the latch lugs 90 and permit them to move outwardly and releasefrom the mandrel detent 91, thereby permitting upward movement of theoperating mandrel 38 relative to the control sleeve 88 and the dragmechanism 92.

A slip setting sleeve 101 extends downwardly from the control sleeve 88and terminates in spaced relation to the upper portions 81 of the slips72. When the retainer sleeve 80 is removed upwardly, the slips '72 arenot restrained and can move outwardly to engage the well casing. Outwardmovement of the slips will, of course, remove the shoulders 78 and 79from engagement with the mandrel and sub grooves 76 and 77 and thethereby uncouple the packer mandrel 11 from the extension assembly. Withthis condition of parts, the extension 45 can telescope upwardlyrelative to the packer mandrel 11 until the coupling lugs 52 engage therecess shoulders 56. Then upward extension movement will shift thepacker mandrel 11 upwardly relative to the setting sleeve 101, thelatter part not moving upward by virtue of the engagement of thefriction drag blocks 95 with the well casing. Accordingly, it will beappreciated that the slip segments 72 cannot move upwardly due to theholding action of the setting sleeve 101, and that the expander cone 17can be moved upwardly and behind the slips 72 to shift them outwardlyinto firm anchoring engagement with the well casing. Once the upperslips 72 are set, the expander cone 17 cannot move any further upwardlyand continued upward movement of the mandrel 11 will advance the lowercone toward the upper cone to expand the packing 16. The lower slips 14are shifted over the lower expander cone 1S and outwardly into grippingengagement with the well casing. The ratchet ring 20 will lock the partsin expanded position in conventional manner.

In response to successive upward and downward motions of the extension45 relative to the packer mandrel 11 occasioned by like motions impartedto the running-in string 10 once the packer B is set, the extension 45is caused to rotate through various rotational positions due tointerengagement of index pins 104, extending inwardly within the bore ofthe mandrel 11, with an extension slot system 105 to be described below.Rotation of the extension 45 within the packer mandrel 11 serves toselectively rotate the valve sleeve 27 between open and closedpositions. As shown in plan view in FIGURE 5, the slot system 105 isformed about the periphery of extension 45 and includes verticallydisposed entrance and exit slots 106 and 107 located on opposite sidesof the extension. Inasmuch as the slot system is symmetrically arrangedaround the circumference of the extension 45, for purposes of brevity,only one-half of the total slot system structure will be described andit will be appreciated that each slot portion mentioned hereafter has anidentical counterpart location on the opposite side of the extension.Between these entrance and exit slots 106 and 107 are upper pockets 108and 109, the left upper pocket 108 being located, for example, about 50degrees from entrance and exit slot 106 and the right upper pocket 109being located, for example, about 40 degrees from entrance and exit slot107. An intermediate pocket 110 is located between the upper pockets 108and 109 and can be located about 50 degrees from the left upper pocket108. The entrance and exit slot 106 is connected to the upper pocket 108by a channel 111 which extends upwardly and to the right, and the upperpocket 108 is connected to the intermediate pocket 110 by a channel 112which extends downwardly and to the right. The intermediate pocket 110is connected to the upper pocket 109 by a channel 113 which extendsupwardly and to the right like channel 111, and the upper pocket 109 isconnected to the entrance and exit slot 107 by a channel 114 whichextends downwardly and to the right like channel 112. The intersectionsof the channels 111 and 112, and 113 and 114, are located somewhat tothe left of the respective centers of the upper pockets 108 and 109 sothat the index pin 104 is constrained to enter the channel 112 whenleaving pocket 108, and channel 114 when leaving pocket 109. Moreover,the intersection of channels 112 and 113 is located somewhat to the leftof the intermediate pocket 110 so that the index pin 104 will enter thechannel 113 when leaving the pocket 110.

It will be apparent that the slot system 105 provides a guideway inwhich the pins 104 engage to cause a predetermined sequence ofrotational movements of the extension 45 and the valve sleeve 27relative to the mandrel 11 in response to successive upward and downwardmotions of the extension. Thus, movement of the index pin 104 fromentrance and exit slot 106 to the left upper pocket 108 will cause theextension 45 to rotate about 50 degrees in a clockwise direction (viewedfrom above) within the packer mandrel 11, such rotation being occasionedby engagement of the upper inclined wall 115 of channel 111 with theindex pin. Movement of the index pin 104 from the upper pocket 108 tothe pocket 110 will cause another 50 degrees rotation of the extension45 when the lower inclined wall 116 of the channel 112 engages the indexpin 104, and further movement from the pocket 110 to the right upperpocket 109 will cause an additional 40 degrees relative rotation whenthe index pin engages the upper inclined wall 117 of the channel 113.Finally, movement of the index pin 104 from the right upper pocket 109down through the channel 114 with inclined lower wall 118 and out of theentrance and exit slot 107 will effect another degrees relative rotationof the extension for a total of 180 degrees. Each increment of extensionrotation will cause a corresponding amount of rotation of the valvesleeve 27 by virtue of engagement of the valve sleeve pins 35 with thewalls 63a of the slots 62 in the torque sleeve 60. Of course thedirection of rotation of the extension 45 and the valve sleeve 27 is afunction of the slot system 105 and, although the arrangement shown ispreferred, it will be appreciated that the slot system 105 could bearranged in reverse manner so that the extension and valve will rotatein the left-hand direction.

The coupling lugs 52 on the extension 45 are vertically aligned relativeto the entrance and exit slots 106 and 107, and the mandrel recessopenings 54- and 55 (FIGURE 3) aligned relative to the index pins 104,such that when the index pins 104 engage within the entrance and exitslots, the coupling lugs 52 are vertically aligned with the mandrelrecess openings and can readily pass into, and out of, the mandrelrecess 53. However, when the index pins 104 engage the upper wallsurfaces 115 of the channels 111 which are inclined upwardly and to theright, the extension 45 is caused to rotate or swivel in the clockwisedirection to position the coupling lugs 52 underneath the mandrelshoulders 56. The lugs 52 will remain in positions underneath themandrel shoulders 56 as long as the entrance and exit slots 106, 107 arenot aligned with the index pins 104, and when the index pins 104 areWithin the intermediate pockets 110, the lugs 52 can engage the mandrelshoulders 56 in order to limit upward movement of the extension 45relative to the packer mandrel 11. The entrance and exit slots 106'and107 are also circumferentially located relative to the torque sleeveslots so that when the index pins 104 are within the slots 106 and 107,and thus when the coupling lugs 52 can pass through the recess openings54 and 55, the valve sleeve 27 is always in a closed rotationalposition. The bosses 120 formed between the entrance and exit slots 106and 107 can have lower converging cam surfaces 121 and 122 to insurethat the mandrel index pins 104 will enter one or the other of the slots106 and 107 regardless of the initial rotational position of theextension 45 relative to the packer mandrel 11 When the extension isinserted. Moreover, the pins 104 can have flattened peripheral portionsto reduce bearing loads as the pins work withtin the slot system 105.

Should it ever be desirable to disconnect the setting tool A from thewell packer B, leaving the extension 45 within the bore of the packermandrel 11, for example, where the extension 45 has become lodged withinthe mandrel by sedimentation or junk in the well, a safety feature iprovided for this puropse. With particular reference to FIGURES 1A and6, the swivel section 48 has a reduced diameter portion 125 which isexternally threaded with buttress type teeth 126 facing upwardly Aclutch ring 127 is cut through at 129 and is capable of sufficientlateral expansion and contraction for ratcheting action over the teeth126 in an upward direction. A longitudinally extending key 130 on theswivel sleeve 44 engages within the cut 129 to co-rotatively secure thering to the sleeve. The swivel section 48 further has an upper outwardlyextending annular shoulder 131 having an inwardly and upwardly inclinedlower face 132 which is shaped in complimentary manner to the upper endsurface of the clutch ring 127.

It will be appreciated that due to the configuration of the slot system105 and its coaction with the indexing pins 104, the extension 45 willalways rotate relative to operating mandrel 35 in the same direction,for example, with the slot arrangement shown in FIGURE 5, in theclockwise or right-hand direction viewed from above. Accordingly, thethreads 126 and 128 on the section 125 and clutch ring 127 respectivelycan be formed as righthand threads. Thus, clockwise rotation of theswivel sleeve 44 and the clutch ring 127 relativ to the operatingmandrel 38 will cause downward feeding of the clutch ring until it abutsthe sub shoulder 134 as shown in FIGURE 1A, whereupon the clutch ringwill remain stationary and merely ratchet over the threads 126 inresponse to continued rotation of extension assembly relative to theoperating mandrel during normal operation of the tool. However, if theoperating mandrel 38 is rotated in a clockwise of right-hand directionrelative to the extension assembly by right-hand rotation of therunning-in string 10 at the top of the well bore, the clutch ring 127will feed upwardly along the threads 126 until the inclined surfaces 132and .133 engage, thereby exerting inward force on the clutch ring andclutching the operating mandrel 38 to the swivel sleeve 44 since theclutch ring cannot ratchet downwardly along the threads 126. Then,continued rotation of the running-in string 10 will effect unscrewing ofthe threads 43 between the swivel sub 42 and the extension 45, whichthreads are formed as left-hand threads, so that the entire setting toolA except for the extension 45 can be withdrawn from the well.

OPERATION In operation, the parts can be assembled as shown in thedrawings with the extension 45 telescoped within the packer mandrel 11.The slips 15 and 72 and the packing 16 are in normally retractedpositions, the upper slips 72 being retained inwardly by the retainersleeve 80. The drag blocks 95 can slide along in frictional engagementwith the well casing as the tool is lowered into a well bore to settingdepth. If it is desired to lower the packer with the valve sleeve 27 inopen condition so that the running-in string 10 can fill with well fluidduring lowering, the extention 45 is merely inserted into the packermandrel 11 during assembly and the index pins 104 will properly indexthe extension until the pins are in the left upper pockets 108, orpositions D, FIGURE 5. This rotational position of the extension 45 willproperly align the sleeve and body ports 28 and 26 in registry with oneanother. On the other hand, to run the tool in the well with the valvesleeve 27 in closed condition, the plug 25 at the lower end of themandrel 11 can be conveniently removed to gain access to the valvesleeve 27 to position the pins 35 within the enlarged slot portions .64on the torque sleeve 60. This will orient the valve sleeve 27 in arotationally closed position. Inasmuch as the valve sleeve 27 is alwaysrotated in the same direction by the extension 45, the enlarged portions64 have no etfect on the operation of the valve sleeve 27 after the wellpacker is set. In other words, the straight sides 63a of thelongitudinal slot portion 63 always engage the sleeve pins 35 to rotatethe valve sleeve.

When it is desired to set the packer B, the running-in string 10 isfirst rotated a number of turns to the right. Since the drag mechanism92 cannot rotate due to engagement of the drag blocks 95 with thecasing, the control sleev 88 will be rotated relative to the dragmechanism 92 with resultant upward feeding of the retainer sleeve out ofencompassing relation to the upper portions 81 of the upper slips 72. Inactuality, the entire apparatus in the well except for the dragmechanism 92 and retainer sleeve 80 will be rotated by the running-instring 10. When th retainer sleeve 80 moves sufiiciently upwardly, theslips 72 are free to move outwardly and the lower end of the settingsleeve 101 is cleared for engagement with upper end surfaces of theslips 72. The cage recess 100 is now positioned adjacent to the latchlugs so that the lugs can move outwardly and release from th mandreldetent 91. The operating mandrel 38 is thus free to be moved upwardlyrelative to the control sleeve 88, the drag mechanism 92 and the settingsleeve 101.

The running-in string is then elevated to set the packer B. When theslips 72 are released, as previously described, the extension 45 canmove upwardly to a limited extent relative to the packer mandrel 11. Asthis relative movement occurs, the extension 45 is rotated as the indexpins 104 move within the intermediate pockets 110, or positions E,FIGURE 5. This rotation of the extension also positions the couplinglugs 52 underneath and in engagement with the mandrel recess shoulders56, the lugs moving from positions G to positions H as shown in FIGURE3. If the valve is initially open, rotation of the extension 45 willalso cause corresponding rotation of the valve sleeve 27 to closedposition. On the other hand, if the valve sleeve 27 is initially closedduring lowering, rotation of the extension 45 will have no effect on thevalve sleeve because the enlarged slot portions 64 in the torque sleeve60 will permit this extension rotation to occur without impartingcorresponding rotation to the valve sleeve. Thus, the valve sleeve 27will remain in closed position.

Inasmuch as the coupling lugs 52 are engaging the mandrel shoulders 56,continued upward movement of the extension 45 will elevate the packermandrel 11, and thus the upper expander cone 17, toward the lower endsurface of the setting sleeve 101. The slips 72 will thus 8 be shiftedoutwardly into gripping engagement with the casing, the holding force ofthe drag blocks 95 being transmitted through the cage 93, threads 94,control sleeve 88 to the setting sleeve 10:1 to prevent its upwardmovement. The slips 72 will accordingly be held against upward movementby the setting sleeve 101 and sutficient upward movement of the packermandrel 11 will bring the expander cone 17 behind the slips 72 to shiftthem outwardly into gripping engagement with the casing as shown inFIGURE 7B. When the upper slips 72 grip the casing, the upper expandercone 17 cannot move any further upwardly, and continued upward movementof the packer mandrel 11 will cause expansion of the packing element 16and then shifting of the lower slips 14 over the lower expander cone.15. The external body teeth 21 will ratchet through the ratchet ringand the ring will trap the mandrel 11 in the highest position to whichit is moved. Accordingly, the packing and slips are locked in expandedpositions and when a predetermined upward strain is taken on therunning-in string, the packer B will be firmly set.

After thus setting the packer B, the weight of the running-in string 10is slacked off. This will occasion downward movement of the extension 45within the packer mandrel 11 with consequent rotation of the extensionand string 19 is closed-01f at its lower end and can be pressure Itested for leakage at this time. The weight of the runningin string 10can be conveniently imposed upon the packer B so that pressurizing thestring 10 will not cause the extension as to be lifted upwardly by thepressure. The feature of being able to impose tubing weight on the toolwhen testing tubing is an important advantage over packers of this typehaving reciprocating sleeve valves because the imposition of tubingweight may open the valve systems of these packers.

After such testing, the running-in string 11 is simply picked up at thesurface to disengage the extension 45 from within the bore of the packermandrel 11. As the extension 45 is moved upwardly, the index pins 104will cause the extension and the valve sleeve 27 to rotate again as theindex pins move within the entrance and exit slots 107. The valve sleeve27 is still closed. In this relative rotational positions of parts thecoupling lugs 52 are moved from positions K, FIGURE 3, into verticalalignment with the mandrel recess openings 54, 55. Accordingly, theextension 45 is conditioned to be withdrawn from the bore of the packermandrel 11. It will be noted that whenever the extension 45 iswithdrawn, the valve sleeve 27 is always left in a closed rotationalposition, whereby the well packer B completely bridges the well bore toprevent fluid flow in either longitudinal direction.

To perform a pressure operation such as squeeze cementing, the extension45 is reinserted within the bore 12 of the packer mandrel 11 by downwardmovement of the running-in string 10. Regardless of the initial randomrotational position of the extension 45, the bosses 120 and the lowercam surfaces 121 and 122 will cooperate with the index pins 104 toproperly orient the extension 45 such that the index pins are verticallyaligned within the entrance and exit slots 106 and 167. With the slots106 and 107 thus aligned, the coupling lugs 52 are also aligned with themandrel recess openings 54, 55, and the side slots 62 in the valvetorque sleeve 60 are properly positioned with respect to the valvesleeve pins so that the lower end portion 59 of the extension can belowered inside the valve sleeve 27. l/Vhen the extension has movedsufiiciently downwardly within the bore of the packer mandrel 11, theindex pins 104 will engage the upper inclined surfaces 115 of thechannels 111 and cause the extension and the valve sleeve 27 to rotateduring further downward movement until the index pins are within theleft upper pockets 108. As this rotation occurs, the valve sleeve ports28 will become radially aligned with the valve body ports 26 to open thevalve. The coupling lugs 52 are also rotated to positions within themandrel recess 53 such that the lugs are underneath the recess shoulders56. With the valve open, cement slurry can be displaced through therunning-in string 10 and out into the well bore below the packer.

When sufficient displacement has occurred and it is desired to trap thesqueeze, e.g., to retain the cement slurry at developed pressures belowthe packer B, the valve sleeve 27 can be moved to a rotationally closedposition by simply picking the running-in string 10 upwardly to indexthe extension 45 until the index pins 104 are within the intermediatepockets 110, thereby rotating the valve sleeve 27 to closed position.The coupling lugs 52 will engage the mandrel shoulders 56 to limitupward movement and thereby positively prevent separation of theextension 45 from the mandrel 11, thus enabling complete control oftubing and annulus pressures. It will be appreciated that adequateannulus pressures can be maintained to prevent dumping cement into wellbore when the extension 45 is purposely disengaged. The extension 45 canbe withdrawn from the packer mandrel 11, leaving the sleeve valve 27 inclosed position, by imparting a pair of vertical motions to therunning-in string 10, one downward, and one upward. The correspondingreciprocation of the extension 45 will cause the index pins 164 totraverse the channels 113 and 114 and into the entrance and exit slots1%, whereupon the coupling lugs 52 are vertically aligned with themandrel recess openings 54, and the extension 45 is free for upwardmovement, leaving the valve sleeve 27 in closed condition. The settingtool A can be withdrawn from the well, or conventional circulation orreverse circulation procedures can be undertaken. Of course, theextension 45 can be reinserted within the packer mandrel 11 for furtheroperations as desired.

lthough the packer B is disclosed as settable on the mechanical settingtool A, it will be appreciated that the packer can be set by the variouswireline or other setting tools which are conventional in the art. Incase of wireline setting, of course other slips such as conventionalfrangible or solid type slips, can be utilized, and the plug 25 at thelower end of the mandrel 11 is provided with internal threads forconnecting to the tension member of the setting tool. Thus it will beapparent that apparatus of the present invention is quite versatile andcan be used for a variety of down hole applications as will beappreciated by those skilled in this art.

A new and improved well packer and valve system have been disclosed foruse in a well bore. The valve system comprises a rotating sleeve whichis mechanically operated in response to a successinn of upward anddownward motions of the pipe string at the top of the well bore. Thepacker can be set and the valve system operated in a convenient,positive, and reliable manner by a minimum number of manipulations.Since certain changes or modifications may be made in the presentinvention by those skilled in the art without departing from theconcepts involved, it is intended that the appended claims cover allsuch changes or modifications falling within the true spirit and scopeof the present invention.

I claim:

1. A well too comprising: a valve body having a iiow passage; a valvesleeve having port means mounted in said valve body for rotationalmovements between positions opening and closing said flow passage; atubular valve actuating means sealingly and rotatably slidable in saidflow passage, said actuating member having a lower end portion coupledto said valve sleeve and an upper end portion adapted for connection toa pipe string; and coengageable means on said valve body and saidactuating means responsive to more than one sequence of downward andupward longitudinal movements of a pipe string for rotating saidactuating means and thus said valve sleeve between positions opening andclosing said flow passage.

2. The well tool of claim 1 wherein said coengageable means includesguideway mean-s on said actuating means and index means on said valvebody cooperable with said guideway.

3. The well tool of claim 2 wherein said guideway means comprises atleast one channel means having opposite end portions opening toward thelower end of said actuating means and at least one transverselyextending cam surface whereby passage of said index means rela tivelythroughout said guideway means eifects predetermined angular movement ofsaid actuating means relative to said valve body.

4. The well tool of claim 2 wherein said guideway means comprises atleast one channel means extending generally longitudinally as well ascircumferentially on said actuating means, said channel means havingopposite end portions opening toward the lower end of said actuatingmeans, said channel means having inclined wall surfaces cooperable withsaid index means in response, to successive pairs of longitudinalmotions of the pipe string to rotate said actuating means betweenpredetermined angular positions with respect to said valve body.

5. A well too comprising: a body member having a fiow passage and beingarranged for anchoring a well conduit; rotatable valve means in saidbody member for opening and closing said flow passage; a tubularactuator extending into said flow passage and slidably and co-rotativelycoupled to said valve means; swivel means for connecting the actuator tothe lower end of a pipe string so that said actuator can rotate relativeto the pipe string and body member; and means for rotating said actuatorand valve means relative to the body member and pipe string in responseto successive upward and downward motions of the pipe string, includinga circumferentially extending guideway on said actuator and index meansengaging in said guideway, said guideway being constructed and arrangedto effect a predetermined sequence of rotational movements of saidactuator and valve means in response to said upward and downward motionsof the pipe string.

6. The well tool of claim 5 wherein said guideway comprises channelmeans recessed in the periphery of said actuator, said channel meanshaving opposite end portions opening toward the lower end of saidactuator, said channel means further having a generallycircumferentially extending portion having inclined upper and lowerwalls for translating successive pairs of longitudinal reciprocations ofthe pipe string to predetermined angular movements of said actuator andvalve means.

7. The well tool of claim 6 wherein said channel means extends entirelyaround the periphery of said actuator means and said index meanscomprises opposed pin means on said body member extending radiallyinwardly toward the axis of said body member.

8. A well tool comprising: a valve body having a flow passage; valvemeans in said valve body mounted for rotational movements betweenpositions opening and closing said flow passage; a tubular valveactuating member ealingly and rotatably slidable in said flow passage,said actuating member hving a lower end portion releasably coupled tosaid valve means for rotating said valve means; coengageable means forrotating said actuating means and valve means in response to successivedownward and upward longitudinal movements of the pipe string; and meansfor limiting alternate upward movements of said actuating member.

9. The well tool of claim 3 wherein said limiting means comprises recessmeans in said body having opposite end portions which are opened towardthe upper end of said body, said recess means having an upper transversewall surface, and means on said actuating means engageable with saidwall surface.

10. The well tool of claim 8 further including means for limitingsuccessive downward movements of said actuating member.

11. The well tool of claim 10 wherein said limiting means comprisescoengageable-transverse surfaces on said actuating means and said body.

12. A well tool comprising: a valve body having a flow passage; valvemeans in said valve body arranged for movement between positions openingand closing said flow passage; a tubular valve actuating membersealingly slidable in said flow passage, said actuating member having alower end portion adapted to be coupled to said valve means and releasedfrom said valve means in response to a predetermined sequence ofdistinct manipulations of said actuating member, said actuating memberand valve body responsive to at least three distinct manipulations ofsaid actuating member for controlling movement of said valve means priorto release of said actuating member.

References Cited UNITED STATES PATENTS 2,998,077 8/1961 Keithahn 166-2263,319,925 5/1967 Kojima et al. 251-58 3,334,691 8/1967 Parker 166-1523,351,133 11/1967 Clark et al. 166-226 X 3,386,701 6/1968 Potts 166-2263,414,061 ,12/1963 Nutter 166-226 DAVID E. BROWN, Primary Examiner US.Cl. X.R.

